1. Field of the Invention
Embodiments described herein are directed toward artificial lift systems used to produce fluids from wellbores, such as crude oil and natural gas wells. More particularly, embodiments described herein are directed toward an improved anchor for use with a downhole pump. More particularly, the embodiments described herein are directed to a resettable anchor configured to prevent longitudinal and rotational movement of the pump relative to a tubular.
2. Description of the Related Art
Modern oil and gas wells are typically drilled with a rotary drill bit and a circulating drilling fluid or “mud” system. The mud system (a) removes drill bit cuttings from the wellbore during drilling, (b) lubricates and cools the rotating drill bit, and (c) provides pressure within the borehole to balance internal pressures of formations penetrated by the borehole. Rotary motion is imparted to the drill bit by rotation of a drill string to which the bit is attached. Alternately, the bit is rotated by a mud motor which is attached to the drill string just above the drill bit. The mud motor is powered by the circulating mud system. Subsequent to the drilling of a well, or alternately at intermediate periods during the drilling process, the borehole is cased typically with steel casing, and the annulus between the borehole and the outer surface of the casing is filled with cement. The casing preserves the integrity of the borehole by preventing collapse or cave-in. The cement annulus hydraulically isolates formation zones penetrated by the borehole that are at different internal formation pressures.
Numerous operations occur in the well borehole after casing is “set”. All operations require the insertion of some type of instrumentation or hardware within the borehole. Examples of typical borehole operations include: (a) setting packers and plugs to isolate producing zones; (b) inserting tubing within the casing and extending the tubing to the prospective producing zone; and (c) inserting, operating and removing pumping systems from the borehole.
Fluids can be produced from oil and gas wells by utilizing internal pressure within a producing zone to lift the fluid through the well borehole to the surface of the Earth. If internal formation pressure is insufficient, artificial fluid lift devices and methods may be used to transfer fluids from the producing zone and through the borehole to the surface of the Earth.
One common artificial lift technology utilized in the domestic oil industry is the sucker rod pumping system. A sucker rod pumping system consists of a pumping unit that converts a rotary motion of a drive motor to a reciprocating motion of an artificial lift pump. A pump unit is connected to a polish rod and a sucker rod “string” which, in turn, operationally connects to a rod pump in the borehole. The string can consist of a group of connected, essentially rigid, steel sucker rod sections (commonly referred to as “joints”) in lengths, such as twenty-five or thirty feet (ft), and in diameters, such as ranging from five-eighths inch (in.) to one and one-quarter in. Joints are sequentially connected or disconnected as the string is inserted or removed from the borehole, respectively. Alternately, a continuous sucker rod (hereafter referred to as COROD) string can be used to operationally connect the pump unit at the surface of the Earth to the rod pump positioned within the borehole. A delivery mechanism rig (hereafter CORIG) is used to convey the COROD string into and out of the borehole.
Prior art borehole pump assemblies of sucker rod operated artificial lift systems typically utilize a progressing cavity (PC) pump positioned within wellbore tubing. FIG. 1A is a sectional view of a prior art PC pump 100. A pump housing 110 contains an elastomeric stator 130a having multiple lobes 125 formed in an inner surface thereof. The pump housing 110 is usually made from metal, preferably steel. The stator 130a has five lobes. Although, the stator 130a may have two or more lobes. Inside the stator 130a is a rotor 118. The rotor 118 having one lobe fewer than the stator 130a formed in an outer surface thereof. The inner surface of the stator 130a and the outer surface of the rotor 118 also twist along respective longitudinal axes, thereby each forming a substantially helical-hypocycloid shape. The rotor 118 is usually made from metal, preferably steel. The rotor 118 and stator 130a interengage at the helical lobes to form a plurality of sealing surfaces 160. Sealed chambers 147 between the rotor 118 and stator 130a are also formed. In operation, rotation of the sucker rod or COROD string causes the rotor 118 to nutate or precess within the stator 130a as a planetary gear would nutate within an internal ring gear, thereby pumping production fluid through the chambers 147. The centerline of the rotor 118 travels in a circular path around the centerline of the stator 120.
One drawback in such prior art motors is the stress and heat generated by the movement of the rotor 118 within the stator 130a. There are several mechanisms by which heat is generated. The first is the compression of the elastomeric stator 130a by the rotor 118, known as interference. Radial interference, such as five-thousandths of an inch to thirty-thousandths of an inch, is provided to seal the chambers to prevent leakage. The sliding or rubbing movement of the rotor 118 combined with the forces of interference generates friction. In addition, with each cycle of compression and release of the elastomeric stator 130a, heat is generated due to internal viscous friction among the elastomer molecules. This phenomenon is known as hysteresis. Cyclic deformation of the elastomer occurs due to three effects: interference, centrifugal force, and reactive forces from pumping. The centrifugal force results from the mass of the rotor moving in the nutational path previously described. Reactive forces from torque generation are similar to those found in gears that are transmitting torque. Additional heat input may also be present from the high temperatures downhole.
Because elastomers are poor conductors of heat, the heat from these various sources builds up in the thick sections 135a-e of the stator lobes. In these areas the temperature rises higher than the temperature of the circulating fluid or the formation. This increased temperature causes rapid degradation of the elastomeric stator 130a. Also, the elevated temperature changes the mechanical properties of the elastomeric stator 130a, weakening each of the stator lobes as a structural member and leading to cracking and tearing of sections 135a-e, as well as portions 145a-e of the elastomer at the lobe crests. This design can also produce uneven rubber strain between the major and minor diameters of the pumping section. The flexing of the lobes 125 also limits the pressure capability of each stage of the pumping section by allowing more fluid slippage from one stage to the subsequent stages below.
Advances in manufacturing techniques have led to the introduction of even wall PC pumps 150 as shown in FIG. 1B. A thin tubular elastomer layer 170 is bonded to an inner surface of the stator 130b or an outer surface of the rotor 118 (layer 170 bonded on stator 130b as shown). The stator 130b is typically made from metal, preferably steel. These pumps 150 provide more power output than the traditional designs above due to the more rigid structure and the ability to transfer heat away from the elastomer 170 to the stator 130b. With improved heat transfer and a more rigid structure, the new even wall designs operate more efficiently and can tolerate higher environmental extremes. Although the outer surface of the stator 130b is shown as round, the outer surface may also resemble the inner surface of the stator. Further, the rotor 118 may be hollow.
FIG. 2 illustrates a prior art insertable PC pump assembly 200. The PC pump assembly 200 includes a rotor sub-assembly, a stator sub-assembly, and a special production tubing sub-assembly. The special production tubing sub-assembly is assembled and run-in with the production tubing. The production tubing sub-assembly includes a pump seating nipple 236, a collar 238, and a locking tubing joint 240. The pump seating nipple 236 is connected to the collar 238 by a threaded connection. The nipple 236 includes a profile formed on an inner surface thereof for seating a profile formed on an outer surface of a seating mandrel 220. The collar 238 is connected to the locking tubing 240 by a threaded connection. The locking tubing joint 240 includes a pin 242 protruding into the interior thereof. The pin 242 will receive a fork 234 of a tag bar 232, thereby forming a rotational connection. Before the PC pump assembly 200 is positioned and operated down hole, the special production tubing sub-assembly is installed as part of the production tubing string so that the pump will be positioned to lift from a particular producing zone of interest. If the PC pump assembly 200 is subsequently positioned at a shallower or at a deeper zone of interest within the well, this can be accomplished by removing the tubing string, or by adding or subtracting joints of tubing. This repositions the special joint of tubing as required.
The rotor sub-assembly includes a pony rod 212, a rod coupling 216, and a rotor 218. The top of the pony rod 212 is connected to a COROD string (not shown) or to a conventional sucker rod string (not shown) by the connector 214, thereby forming a threaded connection. The pony rod 212 is connected to the top of the rotor 218 by the rod coupling 216, thereby forming a threaded connection. The rotor 218 may resemble the rotor 118. An outer surface of the rod coupling 216 is configured to abut an inner surface of the cloverleaf insert 222, thereby longitudinally coupling the cloverleaf insert 222 and the rod coupling 216 in one direction. The rotor 218 is connected to the rod coupling 216 with a threaded connection.
The stator sub-assembly includes a seating mandrel 220, a cloverleaf insert 222, upper and lower flush tubes 224,226, a barrel connector 228, a stator 230, and the tag bar 232. The seating mandrel 220 is coupled to the upper flush tube 224 by a threaded connection and includes the profile formed on the outer surface thereof for seating in the nipple 236. The profile is formed by disposing elastomer sealing rings around the seating mandrel 220. The cloverleaf insert 222 is disposed in a bore defined by the seating mandrel 220 and the upper flush tube 224 and longitudinally held in place between a shoulder formed in each of the seating mandrel 220 and the upper flush tube 224. The inner surface of the cloverleaf insert 222 is configured to shoulder against the outer surface of the rod coupling 216. The lower flush tube 226 is coupled to the upper flush tube 224 by a threaded connection. Alternatively, the flush tube 224,226 may be formed as one integral piece. The barrel connector 228 is coupled to the lower flush tube 226 by a threaded connection. The stator 230 is coupled to the barrel connector 228 by a threaded connection. The stator 230 may be either the conventional stator 130a or the recently developed even-walled stator 130b. The tag bar 232 is connected to the stator 230 with a threaded connection. A fork 234 is formed at a longitudinal end of the tag bar 232 for mating with the pin 242, thereby forming a rotational connection between the tag bar 232 and the locking tubing 240. The tag bar 232 further includes a tag bar pin 235 (see FIG. 3) for seating a longitudinal end of the rotor 218.
FIG. 3A illustrates the rotor and stator sub-assemblies of the prior art PC pump assembly 200 being inserted into a borehole. The production tubing sub-assembly is installed as part of the production tubing string so that the PC pump assembly 200, when installed downhole, will be positioned to lift from a particular producing zone of interest. Once the production tubing sub-assembly is installed down hole as part of the tubing string, the rotor and stator sub-assemblies are assembled and run down hole inside of the production tubing using a COROD or conventional sucker rod system.
FIG. 3B illustrates the rotor and stator sub-assemblies being seated within the borehole. When reaching the special locking joint 240, the forked slot 234 at the lower end of the assembly tag bar 232 aligns with the pin 242 as shown in FIG. 3B. Once the fork slot 234 aligns with and engages the pin 242, the stator sub-assembly is locked radially within the locking joint 240 and can not rotate within the locking joint 240 when the PC pump assembly 200 is operated. After the fork 234 and pin 242 have aligned and engaged, the seating mandrel 220 will then slide into, seat with, and form a seal with the seating nipple 236. The prior art insertable PC pump assembly 200 is now completely installed down hole.
FIG. 3C illustrates the prior art PC pump assembly 200 in operation, where the rotor 218 is moved up and down within the stator 230 by the action of the pony rod 212 and connected sucker rod string (not shown). After compensating for sucker rod stretch, the sucker rod string is slowly lifted a distance 252, off of the tag bar pin 235 of the tag bar 232. This positions the rotor 218 in a proper operating position with respect to the stator 230.
FIG. 3D shows the system configured for flushing. During operation, it is possible that the insertable PC pump assembly 200 may need to be flushed to remove sand and other debris from the stator 230 and the rotor 218. To perform this flushing operation, the rotor 218 is pulled upward from the stator by the sucker rod string by a distance 254. In order to avoid disengaging the entire pump assembly 200 from the seating nipple 236, the rotor 218 is moved upward only until it is located in the flush tubes 224, 226. The PC pump assembly 200 may now be flushed, and then the rotor 218 reinstalled without completely reseating the entire PC pump assembly 200. Since the prior art insertable PC pump assembly 200 is picked up from the top of the rotor 218, the flush tubes 224, 226 are required. Furthermore, the length of the flush tubes 224, 226 must be at least as long as the rotor 218. The entire PC pump assembly 200 will then be at least twice as long as the stator 230. This presents a problem in optimizing stator length within the operation and clearly illustrates a major deficiency in prior art insertable PC pump systems.
FIG. 3E illustrates the rotor and stator sub-assemblies being removed from the locking joint 240 and seating nipple 236. The sucker rod string is lifted until the rod coupling 216 on the top of the rotor 218 engages with the cloverleaf insert 222. The seating mandrel 220 is then extracted from the seating nipple 236 by further upward movement of the sucker rod string, and the rotor and stator subassemblies are conveyed to the surface as the sucker rod string is withdrawn from the borehole.
The operating envelope of an insertable PC pump is dependent upon pump length, pump outside diameter, and the rotational operating speed. In the prior art PC pump assembly 200, the pump length is essentially fixed by the distance between the seating nipple 236 and the pin 242 of the locking joint 240. Pump diameter is essentially fixed by the seating nipple size. Stated another way, these factors define the operating envelope of the pump. For a given operating speed, production volume can be gained by lengthening stator pitch and decreasing the total number of pitches inside the fixed operating envelope. Volume is gained at the expense of decreasing lift capacity. On the other hand, lift capacity can be gained within the fixed operating envelope by shortening stator pitch and increasing the total number of pitches. Production volume can only be gained, at a given lift capacity, by increasing operating speed. This in turn increases pump wear and decreases pump life. For a given operating speed and a given seating nipple size, the operating envelope of the prior art system can only be changed by pulling the entire tubing string and adjusting the operating envelope by changing the distance between the seating nipple 236 and the pin 242. Alternately, the tubing can be pulled and the seating nipple 236 can be changed thereby allowing the operating envelope to be changed by varying pump diameter. Either approach requires that the production tubing string be pulled at significant monetary and operating expense.
In summary, the prior art insertable PC pump system described above requires a special joint of tubing containing a welded, inwardly protruding pin for radial locking and a seating nipple. The seating nipple places some restrictions upon the inside diameter of the tubing in which the pump assembly can be operated. This directly constrains the outside diameter of the insertable pump assembly. The overall distance between the pin and the seating nipple constrains the length of the pump assembly. In order to change the length of the pump assembly to increase lift capacity (by adding stator pitches) or to change production volume (by lengthening stator pitches), (1) the entire tubing string must be removed and (2) the distance between the seating nipple 236 and the locking pin 242 must be adjusted accordingly before the production tubing is reinserted into the well. Longitudinal repositioning of the PC pump assembly 200 without changing length can be done by adding or subtracting tubing joints to reposition the seating nipple 236 and the locking pin 242 as a unit. The prior art PC pump assembly 200 requires a flush tube 224,226 so that the rotor 218 can be removed from the stator 230 for flushing. This increases the length of the assembly and also adds to the mechanical complexity and the manufacturing cost of the assembly.
Therefore, there exists a need in the art for an insertable PC pump that does not require specialized components to be assembled with a production string.